The Digital Dream and the DER Imperative

The Digital Dream and the DER Imperative

By Gary Rackliffe, VP Smart Grids and Grid Modernizations, ABB

The theme for this ETS18 is “Dream in Digital,” which is fitting given where we are in our collective journey toward a digital grid. In a recent post, Zpryme’s Christine Richards ponders the fact that, despite more than a decade of progress, her vision of “an earth blanketed with seamless sensors and communications along with decentralized, decarbonized energy” has yet to materialize.

In fact, utilities have been deploying AMI for the better part of two decades, but smart meters and their accompanying data streams are just the beginning, and I would argue we’ve come a long way from these humble beginnings.

Distribution automation, and now advanced distribution management systems (ADMS), have introduced a host of applications (e.g., FDIR) that can be managed from a single user interface. This combined with a proliferation of field sensors has created a new challenge: utilities are now awash in data from a growing variety of sources. Still, most are not making the most of it, particularly with regard to operational systems.

The challenge at this point in our digitalization journey is to leverage these myriad data flows to produce actionable information, to translate that data into better operational efficiency, reliability and customer experience. That’s a tall order, and it extends to every aspect of utility operations, so let’s focus on one key aspect, distributed energy resources (DER).

DERs are here to stay, and they are growing in variety and number. This has been widely reported, but here are a few statistics* to put it in perspective:

  • Solar power will reach grid parity in 30 states by the end of next year
  • The US microgrid market is projected to grow by 115% in the five years to 2020
  • The storage market is set to increase five-fold between 2017 and 2022.

Managing disparate assets—whether behind or in front of the meter—requires sophisticated controls based on real-time automation. That, in turn, is predicated on sound engineering, strong analytics and control systems that leverage AMI data, smart inverters and intelligent devices, all linked by robust communication networks.

With these capabilities in place, though, utilities can position themselves to derive value from DER assets instead of simply “managing” their operational challenges.

The potential is huge. Grid-connected hot water heaters, for example, could facilitate the addition of 100 GW of wind and solar in the US according to the Regulatory Assistance Project. Virtual power plants comprised of generation, load and storage resources have the potential to provide even more (e.g., energy, ancillary services, peak shaving, etc.)

That sounds more like Ms. Richards’ vision, doesn’t it?

It’s still relatively early in the DER adoption cycle, but utilities are well advised to start investing now in systems that can grow as the proliferation of DERs ramps up. In particular, they should look for DER management systems (DERMS) that can manage a variety of assets from registration to interconnection to optimization to billing. The DERMS of choice should also allow the grid operator to manage voltage control and power quality, and as noted earlier it should scale easily to manage thousands, even hundreds of thousands of devices in the future.

It’s also important to understand how a DERMS plays with other operational technology. For example, the network model in an ADMS should extend to the DERs under management. This is just one of many hurdles to bringing the digital dream into reality.

Each utility will have to arrive at their own conclusions as to how best to move from simply accommodating DERs to realizing their full value.

For more detail on that and other key elements of the digital grid, check out the ABB-sponsored white paper, “The Digital Grid: Building the Foundation With IoT and Data Analytics,” and be sure to join the discussion at ETS18 in Austin, March 26-29.

*Source: GTM Research



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